The case for intelligent DER applications that analyze, query and visualize not just collect and categorize
The distributed energy resource (DER) landscape has evolved faster than most utility systems were built to handle. Rooftop solar, behind-the-meter batteries, electric vehicle chargers and controllable loads are no longer just a handful of isolated installations per service territory. They are arriving in an entire neighborhood, stacking onto aging distribution circuits designed for a different era. Distribution system operators and planning department leaders at utilities of every size are now grappling with how to understand what they have, where it’s located and what they can do with it.
The answer starts with a DER registry. But that’s just the beginning. Most utilities do not have a single, centralized registry. Instead, they have pockets of data scattered across interconnection databases, billing systems and customer program spreadsheets. That fragmentation has real operational consequences. When utilities attempt to deploy a distributed energy resource management system (DERMS), the intelligent application layer that enables real-time monitoring, control and optimization of DERs, they often find that incomplete underlying data renders advanced functionality out of reach. What utilities need is to build a single, trusted registry that serves as a data engine, fuels modern DERMS applications and supports timely, accurate and critical decision-making.
Why a Simple Database Won’t Solve the Challenges Utilities Face
For decades, the utility industry operated under the practical assumption that DERs were small, infrequent and inconsequential. When a customer wanted to install rooftop solar on their home, the utility said yes, recorded a minimal set of data, perhaps just an address and meter number, and moved on. With a few installations per service territory per year, and with capacity and capital abundant, the interconnection process was little more than a formality.
That era is over. Today, utilities are managing the simultaneous connection of 50 or more homes in a single neighborhood, with rooftop solar arrays and battery storage systems impacting distribution circuits built in the 1970s and already at capacity. Regulators and commissions are not approving capital for new substation construction at the pace needed to build around the problem. Instead, they are directing utilities to operate these existing distribution systems and assets more efficiently. That mandate forces utilities to identify, understand and potentially even control the DER assets already connected to their systems. They cannot do so if they do not know what those assets are, how to communicate with them, what grid services they may be able to provide, or, probably most importantly, where they even are.
Over 60% of utilities struggle with outdated data management systems and antiquated processes, creating a fragmented, siloed environment in which a DER asset can remain on a circuit for years without ever being tracked in a way that makes it operationally useful. Interconnection processes and data collection today can intake attributes, such as control protocol availability of rooftop solar inverters, unheard of 30 years ago. This underscores the gap between data collection and data readiness.
The interconnection process has historically reinforced this blind spot. Smaller, behind-the-meter assets that were not deemed impactful to the distribution circuit could be installed without comprehensive data capture or rigorous engineering studies. These approaches were reasonable policy standards when a 30-MW circuit included three small solar installations. But those standards no longer hold in today’s environment, when that same circuit might be serving 28 MW of load with dozens of behind-the-meter DERs that the utility cannot predict or manage. When a voltage or feeder issue arises, operators often cannot trace the cause because the underlying asset data was never captured.
The assumption that a utility already “has a registry” is more optimistic than accurate. Most utilities have three or four distinct data sets across different systems, maintained by different departments, with no single source of truth. That is not a registry. It is data stored in a fragmented environment. Adding DERMS to that environment without first resolving the data foundation creates a new layer of problems. Utilities deploying DERMS platforms often find they cannot locate DER assets they know exist, or that asset data is too incomplete to enable the advanced functionality they expected.
The core challenges for distribution operators and planning leaders include:
- Fragmented data across multiple systems
- Inconsistent data capture attributes across asset classes
- Non-standardized interconnection processes that vary by department, asset size, type, etc.
- DERMS implementations stalling because the underlying DER data is incomplete
- Growing grid pressure with constrained capital
Building the Foundation
The path forward requires two things to happen in the right order: build a true DER registry with the necessary supporting business processes, and then integrate it as the foundational data layer for a modern DERMS. Neither substitutes for the other. A DERMS without a complete registry has no coherent dataset to manage. A registry without the intelligent application layer that a DERMS provides is a catalog, which is useful, but not actionable at the operational level that the grid now demands.
1. Build the Registry or Verify You Actually Have One
The first question every utility needs to answer honestly is whether a true registry exists. If the data lives in three places, maintained by three departments with no shared schema, then that is a fractured data repository, not a registry. For utilities starting from zero, the task is to build. For those who believe they already have one, the task is to audit. Are all data sources consolidated into a single repository that covers every DER asset, including the necessary data attributes from large commercial installations to residential storage units? If not, the registry is incomplete regardless of its internal name.
2. Centralize All DER Data Sources
Even utilities with genuine investments in DER tracking often find data siloed across organizational functions. The interconnection team captures one set of fields, customer programs another and billing a third. Centralization means breaking down those boundaries and establishing a shared data architecture. Every source that contains DER information needs to be identified and either migrated into the central registry or connected via a reliable integration. This creates a single system of record where any stakeholder can find authoritative, complete asset information.
3. Standardize Data Capture Across All Asset Classes
Standardization means applying uniform data capture requirements across all asset classes. A residential battery installed five years ago, with only an address and meter number on file, may now be one of 300 similar assets on a circuit the utility is trying to optimize. Without nameplate capacity, inverter specifications and control parameters, that asset cannot be enrolled, dispatched or used to help solve the grid problems it might otherwise address. Standardization also means having cross-departmental conversations and documented business processes between planning engineers, system operators and customer programs teams. This aligns with what data is needed versus what has historically been collected.
4. Evaluate and Evolve Interconnection Processes
Interconnection standards need to be applied consistently across the entire organization. They also need to be designed to meet not only today’s data needs but also tomorrow’s, including fields that support advanced DERMS functionality and virtual power plant development. The moment any group is exempt from the standard, the registry begins to degrade. One-off workarounds, however well-intentioned, produce disconnected records and hidden installations that undermine the system of record. It is also worth noting that even if a DERMS is years away on the roadmap, the time to start building the registry is now. Every year of delay means more installations go in without the right data and more retroactive remediation work when the DERMS eventually arrives.
Integrating the Registry with DERMS
For utilities with a DERMS in place or preparing to deploy one, the registry and the management system must work together as a unified platform. Once the DERMS is operational and backed by a complete registry, utilities gain real capabilities. They can identify which assets are contributing to a voltage issue, dispatch them in response to a grid event, enroll customers in a designed demand side management program based on what is installed and model flexible interconnection scenarios using real data. This is what transforms DERs from a grid burden into a grid asset. There are three steps to getting the integration right.
1. Bring in DER Data First
The DER asset registry must be the foundational integration within the DERMS. ADMS for power flow, GIS for map visualization and analysis, CIS for customer information and meter data systems for operational visibility all become exponentially more valuable once they are tied to a known, accurately described DER asset. Without the asset as the anchor, supporting data has no context.
2. Integrate Supporting Systems
Once DER asset data is in place, connect the surrounding systems, including power flow modeling, customer information and meter data. Each integration layer builds on the asset foundation established in step one, providing operators with the complete operational picture needed to monitor, dispatch and optimize DERs in real time.
3. Establish Governance
Technological improvements will not endure without the organizational structure to sustain them. A cross-functional governance model, which brings together distribution planning, customer programs, interconnection, IT and operations, ensures the registry stays current, interconnection standards continue to evolve and no single department creates a separate data source. Without it, the same silos that created the original data problem will quietly reassemble around the new one.
Benefits Achieved
When a utility builds a true DER registry and integrates it with a properly deployed DERMS, the returns span grid reliability, cost management, customer engagement and long-term planning. These outcomes follow directly from having the right data in the right place.
Improved grid situational awareness: Know which assets are on the distribution system, where they are located and gain insight into the causes of voltage, frequency or feeder-level issues without costly reactive troubleshooting.
Reduced truck rolls and manual investigation: Direct field resources based on data-driven insights, reducing operational costs and response time.
Prosumer customer engagement: Identify customers with enrollable DER assets and offer targeted demand-side programs that generate both grid value and customer satisfaction.
Discovery of unknown asset classes: Surface DER populations that were never formally tracked, enabling new program design based on actual inventory rather than assumptions.
System optimization and load factor improvement: Use DER dispatch to improve load factor on existing infrastructure and defer capital investment.
Virtual power plant and flexible interconnection capability: Unlock advanced use cases that treat aggregated DERs as a coordinated grid resource for generation offset and resilience.
Lower operating costs: Reduced truck rolls, demand-side programs, system optimization, and increased hosting capacity all help reduce overall costs.
Next Steps: TRC Can Help
TRC brings a rare combination of depth on both sides of the DER equation, including expertise in DER assets and DERMS technology, alongside deep experience with utility operational units. That dual perspective matters because building a true DER registry and deploying a DERMS as technology projects that deliver maximum business value. It requires breaking down organizational silos, aligning departments that have historically operated independently and driving change across the utility from the inside.
What sets us apart is that our practitioners have been inside utilities creating, driving and delivering these programs, not advising on them from a distance. That hands-on experience means we understand both the technical architecture and the organizational dynamics that determine whether a registry stays current or quietly fragments again within a few years. Whether a utility has no registry, a fragmented one, a DERMS without complete data or a registry without a DERMS, TRC can help identify exactly where the gaps are and build the foundation needed to close them.
To learn more about how we can help your utility build and operationalize a DER registry and DERMS strategy, visit TRC’s Intelligent Grid Solutions or contact us today.
